Field of the Invention
The invention relates generally to the field of multiaxial electromagnetic induction well logging instruments and methods. More specifically, the invention relates to using measurements from multiaxial electromagnetic induction well logging instruments to determine the existence and geodetic orientation of fractures in subsurface rock formations.
Background Art
Electromagnetic (EM) based instruments for measuring properties of matter or identifying its composition, for example that of rock formations penetrated by a wellbore, are well known. The values of electrical properties for earth formations have been obtained through the use of electromagnetic induction instruments for over 50 years. EM propagation well logging devices are also well known, and are used for measuring basic parameters such as amplitude and phase shift of EM waves being propagated through a medium (e.g., subsurface rock formations) in order to determine specific properties of the medium (e.g., conductivity and dielectric constant).
Electrical conductivity (or its inverse, resistivity) is an important property of subsurface rock formations used in geological surveys and prospecting for oil, gas, and water because many minerals, and more particularly hydrocarbons, are less conductive than common porous sedimentary rocks that are typically saturated with water. Thus, a measure of the conductivity is often a guide to the presence and amount of oil, gas, or water in a particular formation. Induction logging methods are based on the principle that time varying electric currents passed through a wire coil or loop, due to the corresponding time varying magnetic flux induced, induce electric currents in rock formations in relation to the electrical conductivity of such formations.
EM propagation well logging instruments generally use multiple longitudinally-spaced transmitter antennas operating at one or more frequencies and a plurality of longitudinally spaced receivers or pairs thereof. An EM wave is propagated from the transmitter antenna into the formation in the vicinity of the wellbore in which the instrument is disposed. The EM wave is detected at the receiver antenna(s). A plurality of parameters of interest can be determined by combining the basic measurements of phase and amplitude of the wave as it is detected with reference to the transmitted EM wave. Such parameters include the resistivity, dielectric constant and porosity (fractional volume of pore space) of the formation as well as, for example, the extent to which the fluid within the borehole migrates into the earth formation.
The transmitter antennas on induction well logging instruments generate a time-varying magnetic field when a time-varying electric current is applied to them. The time-varying magnetic field induces eddy currents in the surrounding earth formations. The eddy currents induce voltage signals in the receiver antennas, which are then measured. The magnitude of the in phase and quadrature components of the induced voltage signals varies in accordance with the formation properties such as those described above. The formation properties can thus be determined from measurements of the components of the induced voltage signals.
Conventional (uniaxial) induction well logging antennas consist of wire coils or solenoids mounted on the instruments with their longitudinal axes (and thus their magnetic dipole moments) parallel to the instrument's central or longitudinal axis. Therefore, the magnetic field induced by passing electric current through such a transmitter coil is also parallel to the central axis of the instrument (which is substantially parallel to the axis of the wellbore). The corresponding induced eddy currents typically flow in loops lying in planes perpendicular to the instrument axis (and thus the wellbore axis).
The response of the described induction logging instruments, when analyzing thinly stratified earth formations, strongly depends on the conductivity of formation layers (strata) oriented parallel to the flow of the eddy currents. Nonconductive layers interleaved within the conductive layers will not contribute substantially to the measured response of the instrument and therefore their contributions to the measured signals will be substantially masked by the conductive layers' response. Accordingly, the nonconductive layers are not detected by typical uniaxial induction well logging instruments when the thicknesses of the interleaved conductive and non-conductive layers are substantially smaller than the axial resolution of the instrument (generally related to the longitudinal spacing between the transmitter and receiver antennas).
Many earth formations consist of conductive layers with non-conductive layers interleaved between them as described above, wherein the layer thicknesses are substantially smaller than the axial resolution of the instrument. The non-conductive layers may be, for example, hydrocarbons disposed in the pore spaces of a porous, permeable rock formation layer. Thus conventional induction well logging instruments are of limited use for the analysis of thinly stratified formations.
Solutions have been proposed to detect nonconductive layers located within conductive layers in thinly stratified rock formations. For example, U.S. Pat. No. 5,781,436 describes a method that consists of selectively passing an alternating current through a plurality of EM induction transmitter coils inserted into the well with at least one coil having its longitudinal axis oriented differently from the axis orientation of the other transmitter coils.
The coil arrangement shown in U.S. Pat. No. 5,781,436, incorporated herein by reference, consists of several transmitter and receiver coils with their centers distributed at different locations along the instrument and with their axes in different orientations. Several coils have the orientation of conventional single axis induction logging instruments, i.e., with their axes parallel to the instrument axis, and therefore to the well axis. Other coils have their axes perpendicular to the instrument axis. This latter arrangement of transmitter or receiver coil is usually referred to as a transverse coil.
Thus transverse EM logging techniques use antennas whose magnetic moment is transverse to the well's longitudinal axis. The magnetic moment m of a coil or solenoid-type antenna is represented as a vector quantity oriented parallel to the induced magnetic field, with its magnitude proportional to the corresponding magnetic flux. To a first approximation, a coil with a magnetic moment m can be analyzed as a dipole antenna due to the induced magnetic poles.
In some applications it is desirable for a plurality of differently directed magnetic moments to have a common intersection point. For example, dipole antennas are known to be arranged such that their magnetic moments point along mutually orthogonal directions and have a common center point. An arrangement of a plurality of dipole antennas wherein the induced magnetic moments are oriented orthogonally in three different directions is referred to as a triaxial orthogonal set of magnetic dipole antennas. An example of such an antenna may consist of a solenoid antenna coaxial with the instrument axis and two substantially longitudinally collocated, perpendicularly arranged “saddle” coils. The result of such arrangement is a mutually orthogonal moment triaxial antenna with a common center of each transmitter's magnetic dipole.
A well logging instrument equipped with a plurality of multiaxial antennas such as the one described above offers advantages over an arrangement that uses single axis solenoid coils distributed at different axial positions along the instrument with their axes in different orientations. For example, a 3D triaxial induction tool, such as one known by the trademark RT SCANNER, which is a trademark of the assignee of the present invention, measures 9 separate component apparent conductivity tensors (σm(i,j,k), j,k=1, 2, 3) at each a plurality of axial spacings between respective multiaxial transmitters and multiaxial receivers. Each of the foregoing may be represented by an index i. FIG. 1 illustrates such a triaxial induction measurement system. The apparent conductivity measurements are usually obtained in the frequency domain by actuating the transmitters with a continuous wave (CW) of one or more selected frequencies to enhance the signal-to-noise ratio. However, measurements of the same information content could also be obtained and used from time domain signals, e.g., by passing a transient electric current through the transmitters, using a Fourier decomposition process. This is a well know physics principle of frequency-time duality. Transient current may include direct current that is switched on, switched off, reversed polarity, or may be switched in a sequence such as a pseudorandom binary sequence. The formation properties, such as horizontal and vertical conductivities (σh, σv), relative dip angle (θ) and the dip azimuthal direction (Φ), as well as wellbore and tool properties, such as wellbore fluid (“mud”) conductivity (σmud), wellbore diameter (hd), tool eccentering distance (decc), tool eccentering azimuthal angle (ψ), all affect the foregoing conductivity tensors. FIG. 2 illustrates an eccentered triaxial induction instrument disposed in a wellbore drilled through an anisotropic formation with a particular dip angle. Using a simplified model of layered anisotropic formation traversed obliquely by a wellbore, the response of the conductivity tensors depends on the above eight parameters (σh, σv, θ, Φ, σmud, hd, decc, ψ) in a very complicated manner. The effects of the wellbore and tool to the measured conductivity tensors may be very large even in oil based mud (OBM) environments, that is, even when the wellbore fluid conductivity is very low. Through an inversion technique sold under the trade name RADAR, which is a mark of the assignee of the present invention, the above wellbore/formation parameters can be calculated and the borehole effects can be removed from the measured conductivity tensor. The RADAR process is an inversion routine used for triaxial induction data obtained from the RT SCANNER instrument to perform the following functions: (1) borehole correction for measurements obtained in oil based mud (substantially non-conductive wellbore fluid); and (2) obtain Rh, Rv, dip (θ), azimuth (Φ) of selected formation based on a uniform anisotropic formation model. The RADAR inversion process is offered as a service by the assignee of the present invention and its affiliates.
The formation parameters (σh, σv, θ, Φ) are usually displayed in real-time to help the user make various decisions related to the drilling and completion of the wellbore being examined. The resistivities (the inverse of conductivities σh, σv) of the rock formations are used to delineate low apparent resistivity laminated “pay” zones, i.e., conductive formation layers interleaved with hydrocarbon bearing, higher resistivity layers. The dip and azimuth (θ, Φ) are used to map the structure of the formation in a scale much finer than that provided by surface reflection seismic data.
One of the important items of information that would affect the drilling and completion decisions of the well is whether the well has traversed significant fracture zones. Fractures occur frequently in the formation due to tectonic forces occurring over geological time. Fractures could also be induced by the drilling operation. Large, deep (deep in the sense of extending a long lateral distance from the wellbore) fracture systems can sometime be the key factor that allows the production of oil and gas from pay zones that would otherwise be substantially non-productive. Large, deep fracture systems traversed by the borehole could also causes loss of wellbore fluid (drilling mud). Knowing the location of the fracture zones and the fracture plane orientations can significantly improve drilling and completion decisions.
Very thin fractures with large planar extent filled with electrically substantially non-conductive fluid (oil based mud) may block the induced current in the formation and could produce significant anomalies in the inverted formation parameters compared with those from the same formation without such fractures. The size of the anomalies may depend on the formation's vertical and horizontal resistivity (Rh, Rv, defined as the resistivities parallel to and perpendicular to the layering of the formation), the size of the fracture plane, and the relative dip and azimuth between the fracture plane and the layering structure of the formation. If the fracture plane is nearly parallel to the layering structure of the formation, the effects of the fracture on the triaxial induction measurements are small. On the other hand, if the fracture plane is close to or perpendicular to the layering structure of the formation the effect of the fracture may dominate the response of the triaxial instrument measurements. The most common fracture system encountered in typical wellbores is nearly horizontally layered formations with vertically oriented fractures. Therefore, triaxial induction logging tools can be used to detect and characterize most of the large vertical fracture systems encountered by a typical wellbore.
There are several patents, i.e., “System and method for locating a fracture in an earth formation”, U.S. Pat. No. 6,798,208 B2; “System and method for locating a fracture in an earth formation”, U.S. Pat. No. 6,924,646 B2; and “Method and apparatus for determining the presence and orientation of a fraction in an earth formation”, U.S. Pat. No. 6,937,021 B2, on the subject of using induction measurements to estimate the fracture orientation, the disclosures of which are incorporated herein by reference. All these prior patents have the detection of the existence of fracture in their title and claims. However, none of the above patents specifically discloses how to detect the existence of fracture. All three of the foregoing patents demonstrate that if a large planar fracture is present near the wellbore, the fracture azimuth can be computed from certain measurement components perpendicular to the fracture plane. Such a computation is useless without the capability of identifying the existence of the fracture in the first place. The algorithms described in the foregoing patents would compute a value which may be due to dipping anisotropic formation, and may have nothing to do with the existence of orthogonally oriented fractures. From practical point of view, it is far more important and useful to have a fracture indicator first than to have a means to compute the fracture azimuth assuming a large fracture exists near the wellbore.